Thermal well liner removal method and apparatus

ABSTRACT

The disclosure relates to removing heat expansible well liners from a well by contacting the liner with circulating hot fluid to uniformly increase the temperature of the liner and to assist in freeing the liner from the earth while simultaneously pulling the liner from the well.

United States Patent References Cited UNITED STATES PATENTS [72] Inventor Stanley 0.11utchison Bakersfield, Calif.

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, F. E. Johnston, R. L. Freeland, Jr. and

[54] THERMAL WELL LINER REMOVAL METHOD AND APPARATUS 7 Claims, 1 Drawing Fig.

e relates to removing heat expansiy contacting the liner with circulat- 166/57, 166/302, 166/312 ABSTRACT: The disclosur E2lb 3 l/0:2, ble well liners from a well b ing hot fluid to uniformly increase the temperature of the liner 166/301- and to assist in freeing th liner from the earth while simultaneously pulling the liner from the well.

[50] Field of STEAM SOURCE PAT EN TEU F5823 I97| STEAM SOURCE FOAM.

SOURCE I N V E N T O R STANLEY 0. HUTCHISON THERMAL WELL LINER REMOVAL METHOD AND APPARATUS This invention relates to removing well liners from oil or gas wells and, more specifically, this invention relates to a method which utilizes a thermal gradient uniformly placed on the liner to cause thermally induced movement of the liner thereby assisting in freeing the liner from the formation to provide for removal of the liner from the well.

It is often desirable, particularly in older oil wells, to remove a perforated casing or well liner from its location adjacent a producing interval. As is known in the art, a producing formation is isolated from the well by means of a metal liner. The liner has slots formed therein to permit oil or gas to come through the liner and collect in the well for pumping or otherwise lifting to the surface. The slots assist in preventing sand or other undesirable material from entering the well. In many old wells the slots are no longer performing this function and it is often desirable toremove such liners and replace them with new ones. However, in these older wells many of the liners v have become bonded to the formation and it has been heretofore extremely difficult or impossible'to remove such liners. The removal of liners is a particular problem when the liners are used over an extended interval as, for example, in many California wells.- These liners may be 100 feet long or longer. As is evident, once they become stuck in the well it may be extremely difficult to remove them.

in a broad aspect, the present-invention provides a method of removing a liner from a well which includes the steps of uniformly providinga temperature differential on the liner from its environmental temperature to assist in freeing the liner from the formation and removing the freed liner from the .well. The temperature differential is provided, for example, by

uniformly heating the liner to cause uniform thermal expansion of the liner to assistin breaking the bond between the liner and the fonnation. Lift means are connected to the liner and a force is applied to the liner to lift it from the well when such bond is broken.

In a more specific aspect, the present invention provides for uniformly heating the liner by injecting steam into the well adjacent the lower portion of the liner and circulating such steam up the well in contact with the liner to uniformly increase the temperature of the liner. During such heating the liner is placed in tension by lifting means connected from the surface to the liner. After the liner has been uniformly heated, and if it is not then readily removed from the well, steam injection is halted and the liner is contacted with arelatively cold fluid to cause rapid contraction of the liner to assist in breaking the bond with the formation. After such bond has been broken the liner is pulled from the well by suitable lifting adjacent a well wall. Additional objects and advantages of the present invention will become apparent from the following detailed description read in light of the accompanying drawing which is made a part of this specification and which illustrates the preferred embodiment of apparatus assembled in accordance with the present invention.

The drawing shows an elevation view, partially in section of a well penetrating an oil-producing formation 10. The portion of the well adjacent producing formation contains a perforated or otherwise suitably slotted well liner 12. The well liner 12 is connected by suitable means to a string of casing 14 which extends from the upper portion of producing formation 7 10 through the earth to the surface. In many wells the liner is simply resting on the bottom of the well and is connected to the casing by conventional wedging means. Such wedging means are used to prevent flow in the annulus between the liner and the casing. The casing-liner annulus is not shown in the drawings due to scale problems. As is well known in the art, the outside diameter of the liner 12 is less than the inside diameter of the casing 14 so that the liner may pass through the casing. For example, atypical liner having an outside diameter of 6% inches would utilize liner couplings of 7% inches outside diameter. This liner would be used with casing having an inside diameter of 8 inches to allow passage of a liner formed by coupling together a number of liner sections. The means closing off the liner-casing annulus are removed by conventional methods such as by cutting or reaming at the time it is desired to remove the liner from the well.

After the liner is' so prepared a spear 18 having a set of movable slips 20 is run into the well to a position adjacent the upper portion of the liner 12. The slips 20 can be activated to 1 engage and hold the upper portion of the liner. The spear used means. In certain applications of the present invention is it necessary to provide a circulating fluid'to clean liquid and solid material from the well prior to placing the thermal gradient on the liner. In the preferred form, a stable foam is used as the circulating fluid to remove sand and/or liquid from the well adjacent the liner prior to injecting steam into the well to heat the liner. A suitable technique for producing an injecting such foam is disclosed in my copending application Ser. No. 704,832 filed on Feb. 12, 1968, now US. Pat. No. 3,463,231 for Generation and Use of Foamed Well Circulation Fluids. Thus in accordance with this embodiment of invention a invention a stable foam is produced and injected into the well and circulated up the well to remove sand and liquid from the well. Lifting means are connected to the upper portion of the liner so that a lifting force may be applied to the liner. Steam is injected down the well and circulated past the liner to uniformly heat the liner while a pull is being exerted on the liner by such lifting means. If the liner does not come free from the well after being uniformly heated, a cold fluid is placed in the well adjacent the liner to thermally shock'the liner to assist in breaking the bond between the liner and the formation so that the liner may be removed from the well.

it is an object of the present invention to provide a method of thermally assisting removal of a well liner from a position in the present invention is preferably a circulating spear and thus provides in combination with bumper sub 22 and tubing string 24, a flow path through the lower end of the spear and the surface. Suitable spears for use in accordance with the invention are illustrated on page 388 of the Composite Catalog of Oil Field Equipment and Services for 1968-69. Suitable bumper subs are described on page 404 of this publication. Connected at the lower end of the spear and in communication with such flow path is a tubing tail 26'. The length of the tubing tail is such that when the spear is positioned adjacent the upper portion of the liner the tail will extend to near the bottom of the liner. Thus a flow path is provided from the surface to a position near the lower end of the liner which is to be removed from the well. 7

The tubing string enters the well through a suitable wellhead 28. A slip base plate 30 is connected tothe top of the wellhead and a set of slips 31 are used to hold the tubing string during make up of the string as is known in the art. Stripper rubber 35 is used in the wellhead to prevent leakage of fluid past the tubing where it enters the wellhead. A source of steam 32 is connected to the tubing string 24 by suitable means such as steam hose 34 and pipe 36. Appropriate valves 33 and 38 and connections 40 and 42 are provided on the steam line. The connections 40 and 42 are preferably hammer type joints to facilitate make up and breaking the steam connection while the pipes are hot. The steam line is connected to the tubing string through T connecting 46. Also connected to the tubing string 24 in accordance with the preferred form of the invention is a means for generating foam. The foam source 44 is connected to the other end of the T connection 46 by a foam hose 48 and pipe 50. Suitable valves 52 and 59 and hammertype connections 54 and 56 are provided on the foam line.

The foam source 44 is also connnected to the tubing-casing annulus by means of foam line 51. A suitable valve 53 and hammer connections 55 and 57 are also provided on the foam line 51. Returns from the casing-tubing annulus are vented to the atmosphere by means of blooie line 41. A valve 43 and a hammer connection 45 are also provided on the blooie line. The lifting means for pulling the tubing string and the liner from the well are provided by a hoist means which includes a travelingblock 58 which is moved by suitable cables 60. A

conventional hoist means or derrick, not shown, is used to move the traveling block up or down. The T joint 46 and the upper end of the tubing is held in an elevator 62 which is connected by suitable links 64 to the traveling block 58. Thus when the traveling block moves up or down the tubing string and the apparatus connected thereto are also raised or lowered.

in accordance with the preferred form of the invention when it is necessary to first remove sand and/or well fluids from the well prior to elevating the temperature of the liner, foam is injected down the tubing string 24 through the interiors of bumper sub 22 and spear 18' and down the tubing tail 26 into the well. The foam circulates up the annulus between the tubing tail 18 and the well and through passages 21 in the spear and then to the surface where it is exhausted out of blooie line 41. The foam is used to remove sand liquid. The apparatus for supplying foam to the tubing string utilizes gas pressure for generation of a suitable aqueous-gas foam. Water and a detergent and, if desired, a concentrated caustic solution or other suitable stabilizing agent, are supplied to the foam generation at rates sufficient to produce a foamable mixture. Such a suitable foamable mixture may contain, for example, in parts by weight for each 100 parts thereof, about 0.1 to 1 part of an organic foaming agent, for example, the sodium salt of a linear C C alkyl benzene sulfonic acid mixture. The foamable solution is delivered to the foam generator and a gas, for example air, is also delivered to the foam generator and a foam is formed. Such a suitable foam preferably has a gas-to-liquid volume ratio in the range of 350 to 1. After such a foam has been used to remove undesirable fluid and sand from the well the liner may be uniformly heated to assist in freeing the liner from the formation.

Steam is injected into the well through the flow path provided through tubing string 24, bumper sub 22, spear 18 and tubing tail 26. The steam enters the well adjacent the lower end of the liner 12. The valve 43 on the blooie line 41 is opened during such steam injection to insure that the steam will flow up the well adjacent the liner to uniformly. heat it. The steam flows up the tubing-casing annulus through passageways 21 in spear 18 and thence up the tubing-casing annulus 23 and out the blooie line 41 to atmosphere. This insures that the liner 12 is uniformly heated over its entire length. In this regard it is recognized that the entire liner is not necessarily removed at one time. It is sometimes desirable, especially with very long liners, to cut the liner into sections and remove one section at a time. If this were the case then the upper section of liner alone would first be heated uniformly over its length and removed and then the lower section operated on. w

The spear 18, of course, has been run into the upper end of the liner and the slips 20 moved outwardly to engage the liner prior to steam injection. A pull is exerted on the spear 18 by the lift or hoist means on the surface acting through the tubing string. Steam is injected for a time sufficient to heat the entire liner. The amount of steam is dependent upon the temperature of the formation adjacent the liner, the amount of the fluid in the well, the liner length and the depth of the well. Generally, steam is injected for between 1 to 2 hours. The steam is preferably injected at a rate of between 1,000 and 1,400 equivalent barrels of water per day. Typical steam injection pressures are in the range of abut 400 p.s.i. Steam temperatures at the wellhead have been in the 400' F. range. Steam from 212 F. could be used in certain conditions. An indication that the in liner is heated to steam temperature is given when steam is vented from the blooie line. This indicates that not much condensation is occurring downhole and that, therefore, the downhole environment has been brought up to temperature.

While steam is injected the lift means exerts a pull of about 70 percent to its yield strength to provide a lifting force on the liner. Occasionally the effect of the temperature increase provided by the steam will break the liner loose from the formation and the liner is removed by pulling the tubing and thus the spear and the liner from the well. However, it is often necessary to provide a thermal shock to the liner by quickly cooling it in order to free the liner from the formation. Thus in accordance with the invention a relatively cold liquid is brought in contact with the hot liner to thermally shock it. In actual practice, an ambient temperature fluid is usually suitable. It is preferred to inject the cooling liquid simultaneously down the tubing-casing annulus and the interior of the tubing to rapidly cool the entire liner. Thus both foam lines are opened and ambient temperature water or foam solution is pumped into the well though the both flow paths. The amount of water, of course, will vary depending on the particular conditions of the well. However, successful results have been obtained when 15 barrels of water were pumped down the tubing-casing annulus and 15 barrels of water were simultaneously pumped down the tubing. If after such thermal shock the liner does not break loose in the well, the cycle is repeated. Thus the liner is reheated and rechilled until success is achieved.

Set out below are three actual field runs in which well liners were recovered from old wells utilizing the techniques of the present invention.

CASE ONE Well Identification Well 178, Section 3, 29/28 Kern River Field Mechanical Conditions and Well History After landing 11 inch casing at 336 feet, an 8% inch casing string was carried to 735 feet with cable tools. A wooden plug was placed from 728 feet to 735 feet and the interval 342 feet to 728 feet was perforated with four rows of inches x l inch holes. This well was completed in May, 1910 for an initial production of 39/15 8/0 (O/W). The 8% inch casing was subsequently recovered to 3 l 3 feet and a soft steel 1 1 inch X 8% inch adapter driven on. The latest production rate was 5/0 B/D (OW). Recently, a hydraulically actuated perforating tool was used to reportedly perforate the interval 728 feet to 604 feet.

Program Objectives Drill out the wooden plug and deepen 22 feet. Recover the 8% inch liner, if possible, using new thermal assist technique to evaluate the condition of the liner and to determine the effectiveness of the hydraulic perforator.

Work Dorie On the first day a production hoist was moved in and rigged up. A 3% inch OD bailer located top of fluid at 585 feet and top of fill at 725 feet (3 feet). A foaming unit was moved in and rigged up. On the next work day a 7% inch Hughes OSC-3 bit and two 4%inch drill collars were on 2% inch U.E. tubing. Sand fill was cleaned out from 712 inch to 728 inch, and the wooden plug was drilled out from 728 feet to 738 feet, and the well deepened to 760 feet using foam as the circulating fluid. Pulled. Ran 420 feet of 2 inch tubing, an 8% inch casing spear with a 9.5 inch OD stop collar, a bumper sub, and two 4%inch OD drill collars on 2% inch .I-55 tubing. Circulated out sand fill from 705 feet to 738 feet with foam and then engaged spear and jarred on liner with up to 70,000 pound pulls while circulating foam for 50 minutes. There was no movement of the liner indicated. Foam was shut off and line steam was then circulated down the tubing with the casing-tubing annulus open to the atmosphere. Steam injection rate was 500 B/D (as water) for 28 minutes and 800 B/D for 17 minutes while maintaining a 70,000 pound pull on the liner. The liner came free and was pulled to the surface with a 30,000 to 35,000 pound pull. The liner was dropped when the adapter pulled off and then dropped three more times when it hung up at 40 and 30 feet from the surface. Pulled spear and removed 9.5 inch stop collar and then ran back and engaged liner. Pulled to surface and shut in for the night.

On the next day, pulled and laid down 418 feet of 8% inch liner (422 feet reportedly was in the hole).

CASE TWO Well Identification Well 139, Section 3, 29/28 Kern River Field Mechanical Condition and Well History probably done prior to 19 10. Latest production was 12/4 BID Program Objectives Recover 8% inch liner using a foam circulating system, a regular production hoist, and 2% inch U.E. .l-55 tubing.

Work Performed Moved in production hoist and foaming unit. Pulled and moved out rods an tubing. Ran 3% inch OD bailer. Located top fluid at 665 feet and top fill at 770 feet l 3 feet fill).

Next day had welder cutoff old ll inch casing head and install new shop made wellhead. I

Following day, ran 2% inch tubing tail (to 764 feet) below 8% inch circulating spear, a bumper sub and two 4%inch OD drill collars on 2% inch .l-55 tubing. Engaged 8% inch liner at 418.38 feet and jarred eight times with up to 70,000 pound pull. No liner movement. Circulated'steam down tubing (to 764 feet) with casing-tubing annulus open to the atmosphere while maintaining a 70,000 pound pull on the liner. Steamed for 2 hours minutes with a circulating rate from 400 to 1,000 BID (as water). No movement of liner. Pulled. Ran 7% inch Hughes OSC-3 bit and two 4%drill collars on 2% inch tubing. Cleaned sand 762 feet to 783 feet, drilled out wooden plug 783 feet788 feet, and deepened 788 feet to 803 feet using foam as the circulating fluid. Pulled up to 620 feet an shut in for the night.

Next day, ran bit back to 803 feetno fill; circulated foam for 46 minutes to clear hole. Pulled. Ran tubing tail to 792.45 feet, 8% inch spear, bumper sub, two 4%inch drill collars on 2% inch U.E. J-55 tubing. Engaged liner with spear and pulled 70,000 pounds. No liner movement. Circulated steam down tubing at 1,040 B/D rate with casing-tubing annulus open to atmosphere for 2 hours, 38 minutes while maintaining a 70,000 pound pull on liner. Good steam returns. Injection pressures and temperatures ranged from..320 to 445 p.s.i. and 385 to 4l5 F. respectively. Released spear and pumped barrels of liquid foam mix down tubing to give thermal shock to-liner. Reengaged spear and pulled 65,000 pounds when liner came loose. Drag was about 30,000 pounds while pulling. Pulled and laid down 371.99 feet of 8% inch liner.

CASE THREE Well Identification Well 152, Section 3.29/28. Kern River Field Mechanical Condition and Well History After driving an ll inch casing string to 393 feet, and 8% inch casing string was carried to 753 feet with cable tools. A wooden heaving plug was placed from 749 feet to 753 feet,

' and the interval 396 feet to 749 feet was reportedly perforated with is inch X 1% inch slots using a star perforating tool. The well was placed on production in Nov. 1907. Subsequently,

the 8 inch casing was recovered from 368 feet. Recent production was 4/4 B/D (O/W).

Program Objectives Recover the 8 "76 inch liner.

Work Performed 4.5 inch OD drill collars in the hole. Shut in for the night.

On the next day, finished running in hole. Engage 8% inch liner with circulating spear and tail to 748 feet. Took 70,000 pound pull on liner. No movement. Circulated steam down tubing with casing open to the atmosphere at 750 to 1,340 BID water rate as steam for 2 hours and l5 minutes while maintaining a 70,000 pound pull on the liner. Nomovement. Released spear and pumped 30 barrels of ambient temperatureliquid foam mix down tubing and casing. Worked liner for 40 minutes. No movement. Good steam and oil returns. Reengaged liner and pulled 70,000 pounds. No movement. Circulated steam for 45 minutes when steamgenerator went down. Pumped in 30 barrels of liquid foam mix down tubing and casing. Unable to pull liner loose with 70,000 pounds. Pulled out j of hole and shut in for the night.

On the following day, ran 7% inch bit and drilled wooden plug out of 8% inch shoe and deepened 10 feet to 764 feet. Pulled and laid down 2% inch J-55 tubing. Picked up string of 2% inch U.E. N-80tubing and 8% inch spear assembly. Engaged liner and took l00,000 pound pull. No movement. Circulated steam for 15 minutes while pulling 100,000 pounds. Liner came loose. Pulled and laid down 385 feet of 8% inch liner. 8

As is evident from the above discussion and cases, the present invention provides a method of removing a liner from a well by uniformly heating the liner. The fairly rapid uniform heating of a well liner is readily accomplished with steam as described above. This result canalso be obtained, of course, by circulating hot gases or other suitable heat transfer fluid. Although specific embodiments of the present invention have been described herein, the inventionis not to be limited to only such embodiments but rather by the scope of the ap pended claims.

lclaim:

l. The method of removing a well liner made of a heat expansible material and bonded to a formation in a well comprising the steps of injecting a hot fluid down a well to a location adjacent the lower portion of a well liner, circulating said hot fluid up the well in contact with said liner to uniformly increase the temperature of said liner to assist in freeing said liner from the earth formation adjacent said liner, while simultaneously placing said liner in tension by exerting a lifting force on said liner and removing said liner from the well.

2. The method of removing a well liner made of a heat expansible material and bonded to a formation in a well comprising the steps of injecting steam down a well to a location adjacent the lower portion of a well liner, circulating said steam up the well in contact with said liner to uniformly increase the temperature of said liner to assist in freeing in from the earth formation adjacent said liner, while simultaneously placing said liner in tension by exerting a lifting force on said liner and removing said liner from the well.

3. The method of claim 2 further characterized in that steam injection is halted after the liner is uniformly heated and a cooler fluid is brought in contact with the liner to thermally shock the liner to assist in freeing the liner from the adjacent earth formation.

4. The method of claim 3 further characterized in that a circulating medium is circulated in the well to clean undesirable material from such well prior to injecting steam into the well.

end of said spear means and extending to the lower end of said liner, steam source means for making steam and means connecting said steam source means with said tubing string for injecting steam down said well.

7. The apparatus of claim 6 further characterized in foam source means for making foam and means connecting said foam source means with said tubing string for injection down said well. 

2. The method of removing a well liner made of a heat expansible material and bonded to a formation in a well comprising the steps of injecting steam down a well to a location adjacent the lower portion of a well liner, circulating said steam up the well in contact with said liner to uniformly increase the temperature of said liner to assist in freeing in from the earth formation adjacent said liner, while simultaneously placing said liner in tension by exerting a lifting force on said liner and removing said liner from the well.
 3. The method of claim 2 further characterized in that steam injection is halted after the liner is uniformly heated and a cooler fluid is brought in contact with the liner to thermally shock the liner to assist in freeing the liner from the adjacent earth formation.
 4. The method of claim 3 further characterized in that a circulating medium is circulated in the well to clean undesirable material from such well prior to injecting steam into the well.
 5. The method of claim 4 further characterized in that foam is the circulated medium.
 6. Apparatus for removing well liners from a well comprising a tubing string extending into a well, hoist means connected to said tubing string for lifting and lowering said tubing string, spear means on the lower end of said tubing string for engaging well liner, said spear means having a flow path formed therethrough and in communication with the interior of said tubing string, tubing tail means connected on the lower end of said spear means and extending to the lower end of said liner, steam source means for making steam and means connecting said steam source means with said tubing string for injecting steam down said well.
 7. The apparatus of claim 6 further characterized in foam source means for making foam and means connecting said foam source means with said tubing string for injection down said well. 